The present invention relates to a process for separating carbon dioxide from natural gas using membranes, e.g. semi-permeable membranes. Separating acid gases from untreated natural gas may be referred to as “sweetening” the natural gas. Examples of acid gases that are typically found in untreated natural gas include carbon dioxide (CO2) and hydrogen disulfide (H2S), and untreated natural gas containing one or more of these gases may be referred to as a “sour” gas. The present invention may therefore comprise at least a part of a “sweetening” process for an untreated or “sour” natural gas. The process is intended to enable the production of natural gas of pipeline quality for distribution and use by consumers.
Natural gas deposits containing more than 3% carbon dioxide, and often more than 1.5% carbon dioxide, must be treated to reduce the carbon dioxide content prior to distribution via pipelines. The most common treatment method is chemical absorption within a solvent, which is a solvent wash process typically using an aqueous amine solution such as monoethanolamine (MEA). In such a process, a carbon dioxide-lean amine solution absorbs carbon dioxide from the natural gas to produce a carbon dioxide-enriched solvent which is separated from the natural gas. The solvent is regenerated by applying heat which strips the carbon dioxide from the amine solution. The carbon dioxide is then typically vented to the atmosphere. However, amine absorption systems consume large amounts of energy for solvent regeneration and require significant hazardous chemical inventory.
Membrane treatment is an alternative technology that can offer simpler operation and higher efficiency. Unfortunately, more than one membrane stage is usually required to achieve high natural gas recovery. Typically, the membrane is preferentially permeable to carbon dioxide over methane, but the selectivity is not so high to prevent a significant fraction of the methane to slip into the permeate. This methane slip can be mitigated by the addition of at least one further membrane stage to recover and recycle methane from the permeate, at the cost of additional membranes and power consumption for recompression. Thus, membrane systems typically require carbon dioxide concentrations above about 10% to be economically competitive with treatment processes involving amine absorption.
Scholes et al (Fuel; vol. 96; pp 15-28; 2012) provide a convenient summary of current membrane technology. They describe the physical parameters and performance characteristics of three classes of polymeric membranes, viz. cellulose acetate, polyimides, and perfluoropolymers. Typical CO2/CH4 selectivities range from 4 to 100, although in practice the selectivity can be changed significantly by the nature and amount of the impurities in the natural gas, and temperature.
There are many examples in the art of the use of membranes to remove carbon dioxide from natural gas. For example, Frantz (U.S. Pat. No. 7,429,287A) teaches a multiple stage carbon dioxide removal membrane system that combusts a permeate having a low heating value to generate power.
Baker et al (U.S. Pat. No. 5,558,698A) teaches a membrane system involving one or more stages to remove carbon dioxide and hydrogen sulfide from natural gas that minimizes the concentration of methane in the permeate.
Lokhandwala (U.S. Pat. No. 6,035,641A) teaches of a one stage membrane system that is selective for methane over nitrogen and is used to upgrade a gas stream having a low heating value. The permeate is enriched in methane and used to generate power.
Membranes have also been used to remove carbon dioxide from biogas. For example, Biehl et al (WO2010/006910A) teaches a one stage membrane system that removes carbon dioxide from a biogas feed having a low heating value and containing at least 18 vol. % carbon dioxide with the remainder consisting essentially of methane, water vapor and nitrogen. The system generates as retentate a natural gas stream for distribution that contains preferably less than 15 vol. %, carbon dioxide, together with a permeate stream containing preferably at least 8 vol. %, methane for use in an afterburner in a cogeneration plant.